Hydrocracking is an established, reliable and flexible method for transforming materials such as low-value heavy oil fractions into higher value products. Configuration, catalyst choices and operating conditions of the hydrocracking processes and apparatus used, offer flexibility in, e.g., the selection of feedstock, the products of the hydrocracking, operating efficiency, and profitability. Several process configurations are available, including but not being limited to, once-through for series flow), two-stage, single stage, mild hydrocracking etc., with catalysts. The choice of catalysts and their layering are also important in adapting the general processes to produce the desired products.
Hydrocracking processes are used widely in, e.g., petroleum refineries. They are used to process a variety of feedstocks, which usually boil in the range of 370° C. to 520° C. in conventional hydrocracking units, and boil at 520° C. and above in residue hydrocracking units. In general, hydrocracking processes split the molecules of the feed into smaller, i.e., lighter molecules, having higher average volatility and economic value.
Additionally, hydrocracking processes typically improve the quality of the hydrocarbon feedstock used by increasing the hydrogen to carbon ratio of the products of hydrocracking, and by removing organosulfur and/or organonitrogen compounds. The significant economic benefit derived from hydrocracking processes has resulted in substantial improvements of the process, and in more active catalysts.
Mild hydrocracking, or single stage once-through hydrocracking, occurs at operating conditions that are more severe than standard hydrotreating processes, and which are less severe than conventional, full conversion or high pressure hydrocracking processes. Mild hydrocracking processes are more cost effective, but typically result in lower product yields and quality. They produce less middle distillate products of relatively lower quality, as compared to the products of conventional full conversion or high pressure hydrocracking processes.
Single or multiple catalytic systems can be used in these processes, depending upon the feedstock being processed and the product specifications. Single stage hydrocracking is the simplest of the various configurations, and is typically designed to maximize middle distillate yield over a single or multiple catalyst system. Multiple catalyst systems can be deployed, e.g., as a stacked-bed configuration or in multiple reactors.
In a series-flow configuration, the entire hydrocracked product stream from the first reaction zone, including light gases (e.g., C1-C4 gases, H2S, NH3) and all remaining hydrocarbons, move to a second reaction zone. In the two-stage configuration the feedstock is refined by passing it over a hydrotreating catalyst bed in the first reaction zone. The effluents are passed to a fractionating zone to separate the light gases, naphtha and diesel products which boil at a temperature range of 36° C. to 370° C. The hydrocarbons boiling above 370° C. pass to the second reaction zone for additional cracking.
Conventionally, most hydrocracking processes that are implemented for production of middle-distillates, e.g., those molecules which boil at a range of from about 180° C. to about 370° C. and gasoline, e.g., those molecules which boil at a range of from about 36° C. to about 180° C. after reforming processes.
In all of the above-described hydrocracking process configurations, cracked products, along with partially cracked and unconverted hydrocarbons, are passed to a distillation column for fractionating into products which may include naphtha, jet fuel/kerosene, and diesel fuel, which boil at the nominal ranges of 36° C.-180° C., 180° C.-240° C. and 240° C.-370° C., respectively, and unconverted products which boil at temperatures above 370° C. Typical jet fuel/kerosene fractions (i.e., smoke point >25 mm) and diesel fractions (i.e., cetane number >52) are of high quality and exceed worldwide transportation fuel specifications. Although hydrocracking unit products have relatively low aromaticity, aromatics that do remain have lower key indicative properties (smoke point and cetane number).
In the above-described embodiments, the feedstocks generally include any liquid hydrocarbon feed conventionally suitable for hydrocracking operations, as is known to those of ordinary skill in the art. For instance, a typical hydrocracking feedstock is vacuum gas oil (VGO), which boils at temperatures of 370° C. to 520° C. Other intermediate refinery streams including demetalized oil (DMO) or deasphalted oil (DAO), and coker gas oils from delayed coking units. Cycle oils from fluid catalytic cracking units which can be blended with VGO or can be used as is. The hydrocarbon feedstocks can be derived from naturally occurring fossil fuels such as crude oil, shale oils, coal liquid, or from intermediate refinery products or their distillation fractions such as naphtha, gas oil, or combinations of any of the aforementioned sources.
The catalysts used in first and second stage hydroprocessing reaction zones typically contain one or more active metal components selected from the IUPAC Group 4-10, of the Periodic Table of the Elements. In certain embodiments, the active metal component is one or more of cobalt, nickel, tungsten, molybdenum, or noble metals, such as platinum or palladium, typically deposited or otherwise incorporated on a support, e.g., alumina, silica alumina, silica, titanium or a zeolite or variations thereof which have been modified by, e.g., steam or acid treatment and/or insertion of metals into the zeolite framework.
The first stage process, referred to supra, hydrotreats the feedstock, essentially resulting in removal of nitrogen, sulfur, and sometimes metals contained in the feedstock molecules. Hydrocracking reactions which also take place in the first stage and result in conversion of from 10-65 wt % of the feedstock. As compared to the first stage, second stage processing occurs at lower temperatures, the specifics of which will depend on the feedstock. Exemplary conditions for both stages in these two stage processes include a reaction temperature of from 300° C. to 450° C., a reaction pressure of from 80 to 200 bars, and a hydrogen feed rate below 2500 SLt/Lt.
The catalysts used in the first and second stage may be the same, or different. Typically, a catalyst used in the first stage has an amorphous base (alumina or silica alumina), containing either Ni/Mo, Ni/W, or Pt/Pd when deep hydrogenation is needed. There are, however, process configurations directed to conversion of up to 75 wt % of the feedstock. In such processes, a zeolite catalyst is preferably used. The second stage catalyst may be any of these as well.
To increase the efficiency and profitability of the process, the hydrocracking units are pushed to process heavier feed streams, whether they are deep cut VGO or some other feedstream coming from intermediate refinery processes, such as a coker, an FCC or residue hydroprocessing units. These heavy feedstocks are processed at the cost of reduced cycle length, higher hydrogen consumption, and/or low product yields and quality. New catalysts and/or optimum layering of catalysts are needed to increase the process performance, in addition to optimizing other process parameters, such as better liquid-gas distribution, reactor volume efficiency, etc.
Catalyst layering or loading is well known in the art. For a given objective, hydrocracking catalysts are loaded, based on their functionality, e.g., acidity, and content of active metals, such as Co—Mo (usually used for hydrodesulfurization), Ni—Mo (usually used for hydrodenitrogenation), and Pt/Pd (usually used for hydrogenation for sulfur/nitrogen free hydrocarbons). These practices require lengthy catalyst testing programs to optimize the catalyst layering in the fixed-bed reactor.
Examples of catalytic layering techniques may be seen in, e.g., Published PCT Application 2011/0079540 to Krishna, et al., which describes methodologies where waxy, hydrocarbon feedstocks are contacted to layered catalysts; however, the double bond equivalency, or “DBE” model used by this invention, is not described, nor is the use of sulfur or nitrogen containing compounds, e.g., dibenzothiophenes or cabazoles, as well as derivates thereof, to determine catalytic activity for the layered catalysts. U.S. Pat. No. 5,186,818 to Daage, et al., also fails to teach a DBE model for testing catalysts. U.S. Pat. No. 7,387,712 to Furta, et al., U.S. Pat. No. 4,657,663 to Gardner, et al., and Published PCT Patent Application 2012/0111768 to Elsen, all describe layered catalyst systems, without describing the DBE method, which is key to the invention. U.S. Pat. No. 9,347,006, incorporated by reference, teaches the important interplay of DBE values and layering catalysts.
Also see, e.g., Published PCT Application 1993/021284, U.S. Pat. Nos. 8,163,169; 7,686,949; 6,576,119; 6,086,749; 5,916,529; 5,439,860; 4,822,476; 3,793,190; and 3,617,490, as well as JP 2010163622; JP 2003171671; JP 11080753; and CN 101053846, all of which are incorporated by reference.
It is a purpose of the invention to improve catalyst layering in hydrocarbon cracking processes, by evaluating the feedstock to be treated, and the properties of the catalysts which are employed. At present, standard methods for developing specific hydrocracking protocols use trial and error to select optimum catalytic systems. To elaborate the prior art methods briefly, catalysts are layered, and process performance is measured for each layered system. As this is a trial and error system, extensive testing is required.
The method of the invention varies from the standard methods, as will be shown in the disclosure which follows.